Electric submersible pumping system and method for dewatering gas wells

ABSTRACT

A method of unloading liquid from a reservoir includes deploying a pumping system into a wellbore to a location proximate the reservoir using a cable. The pumping system includes a motor, an isolation device, and a pump. The method further includes setting the isolation device, thereby rotationally fixing the pumping system to a tubular string disposed in the wellbore and isolating an inlet of the pump from an outlet of the pump; supplying a power signal from the surface to the motor via the cable, thereby operating the pump and lowering a liquid level in the tubular string to a level proximate the reservoir; unsetting the isolation device; and removing the pump assembly from the wellbore using the cable.

BACKGROUND OF THE INVENTION

1. Field of the Invention

Embodiments of the present invention generally relate to an electricsubmersible pumping system for dewatering gas wells.

2. Description of the Related Art

As natural gas wells mature, many experience a decrease in productiondue to water build up in the annulus creating back pressure on thereservoir. The gas industry have utilized varying technologies toalleviate this problem, however most do not meet the economic hurdle asthey require intervention such as pulling the tubing string.

SUMMARY OF THE INVENTION

Embodiments of the present invention generally relate to an electricsubmersible pumping system for dewatering gas wells. In one embodiment,a method of unloading liquid from a reservoir includes deploying apumping system into a wellbore to a location proximate the reservoirusing a cable. The pumping system includes a motor, an isolation device,and a pump. The method further includes setting the isolation device,thereby rotationally fixing the pumping system to a tubular stringdisposed in the wellbore and isolating an inlet of the pump from anoutlet of the pump; supplying a power signal from the surface to themotor via the cable, thereby operating the pump and lowering a liquidlevel in the tubular string to a level proximate the reservoir;unsetting the isolation device; and removing the pump assembly from thewellbore using the cable.

In another embodiment, a pumping system includes a submersible highspeed electric motor operable to rotate a drive shaft; a high speed pumprotationally fixed to the drive shaft; an isolation device operable toexpand into engagement with a tubular string, thereby fluidly isolatingan inlet of the pump from an outlet of the pump and rotationally fixingthe motor and the pump to the tubular string; and a cable having two orless conductors, a strength sufficient to support the motor, the pump,and the isolation device, and in electrical communication with themotor. A maximum outer diameter of the motor, pump, isolation device,and cable is less than or equal to two inches.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the manner in which the above recited features of the presentinvention can be understood in detail, a more particular description ofthe invention, briefly summarized above, may be had by reference toembodiments, some of which are illustrated in the appended drawings. Itis to be noted, however, that the appended drawings illustrate onlytypical embodiments of this invention and are therefore not to beconsidered limiting of its scope, for the invention may admit to otherequally effective embodiments.

FIG. 1 illustrates an electric submersible pumping system deployed in awellbore, according to one embodiment of the present invention.

FIG. 2A is a layered view of the power cable. FIG. 2B is an end view ofthe power cable.

FIG. 3 illustrates an electric submersible pumping system deployed in awellbore, according to another embodiment of the present invention.

FIG. 4 illustrates downhole components of the electric submersiblepumping system.

DETAILED DESCRIPTION

FIG. 1 illustrates a pumping system 1 deployed in a wellbore 5,according to one embodiment of the present invention. The wellbore 5 hasbeen drilled from a surface of the earth 20 or floor of the sea (notshown) into a hydrocarbon-bearing (i.e., natural gas 100 g) reservoir25. A string of casing 10 c has been run into the wellbore 5 and settherein with cement (not shown). The casing 10 c has been perforated 30to provide to provide fluid communication between the reservoir 25 and abore of the casing 10. A wellhead 15 has been mounted on an end of thecasing string 10 c. An outlet line 35 extends from the wellhead 15 toproduction equipment (not shown), such as a separator. A productiontubing string 10 t has been run into the wellbore 5 and hung from thewellhead 15. A production packer 85 has been set to isolate an annulusbetween the tubing 10 t and the casing 10 c from the reservoir 25. Thereservoir 25 may be self-producing until a pressure of the gas 100 g isno longer sufficient to transport a liquid, such as water 100 w, to thesurface. A level of the water 100 w begins to build in the productiontubing 10 t, thereby exerting hydrostatic pressure on the reservoir 25and diminishing flow of gas 100 g from the reservoir 25.

The pumping system 1 may include a surface controller 45, an electricmotor 50, a power conversion module (PCM) 55, a seal section 60, a pump65, an isolation device 70, a cablehead 75, and a power cable 80.Housings of each of the components 50-75 may be longitudinally androtationally fixed, such as flanged or threaded connections. Since thedownhole components 50-80 may be deployed within the tubing 10 t, thecomponents 50-80 may be compact, such as having a maximum outer diameterless than or equal to two or one and three-quarter inches (depending onthe inner diameter of the tubing 10 t).

The surface controller 45 may be in electrical communication with analternating current (AC) power source 40, such as a generator on aworkover rig (not shown). The surface controller 45 may include atransformer (not shown) for stepping the voltage of the AC power signalfrom the power source 40 to a medium voltage (V) signal, such as five toten kV, and a rectifier for converting the medium voltage AC signal to amedium voltage direct current (DC) power signal for transmissiondownhole via the power cable 80. The surface controller 45 may furtherinclude a data modem (not shown) and a multiplexer (not shown) formodulating and multiplexing a data signal to/from the PCM 55 with the DCpower signal. The surface controller 45 may further include an operatorinterface (not shown), such as a video-display, touch screen, and/or USBport.

The cable 80 may extend from the surface controller 45 through thewellhead 15 or connect to leads which extend through the wellhead 15 andto the surface controller 45. The cable 80 may be received by slips or aclamp (not shown) disposed in or proximate to the wellhead 15 forlongitudinally fixing the cable 80 to the wellhead 15 during operationof the pumping system 1. The cable 80 may extend into the wellbore 5 tothe cablehead 75. Since the power signal may be DC, the cable 80 mayonly include two conductors arranged coaxially.

FIG. 2A is a layered view of the power cable 80. FIG. 2B is an end viewof the power cable 80. The cable 80 may include an inner core 205, aninner jacket 210, a shield 215, an outer jacket 230, and armor 235, 240.The inner core 205 may be the first conductor and made from anelectrically conductive material, such as aluminum, copper, aluminumalloy, or copper alloy. The inner core 205 may be solid or stranded. Theinner jacket 210 may electrically isolate the core 205 from the shield215 and be made from a dielectric material, such as a polymer (i.e., anelastomer or thermoplastic). The shield 215 may serve as the secondconductor and be made from the electrically conductive material. Theshield 215 may be tubular, braided, or a foil covered by a braid. Theouter jacket 230 may electrically isolate the shield 215 from the armor235, 240 and be made from an oil-resistant dielectric material. Thearmor may be made from one or more layers 235, 240 of high strengthmaterial (i.e., tensile strength greater than or equal to two hundredkpsi) to support the deployment weight (weight of the cable and theweight of the components 50-75) so that the cable 80 may be used todeploy and remove the components 50-75 into/from the wellbore 5. Thehigh strength material may be a metal or alloy and corrosion resistant,such as galvanized steel or a nickel alloy depending on thecorrosiveness of the gas 100 g. The armor may include twocontra-helically wound layers 235, 240 of wire or strip.

Additionally, the cable 80 may include a sheath 225 disposed between theshield 215 and the outer jacket 230. The sheath 225 may be made fromlubricative material, such as polytetrafluoroethylene (PTFE) or lead andmay be tape helically wound around the shield 215. If lead is used forthe sheath, a layer of bedding 220 may insulate the shield 215 from thesheath and be made from the dielectric material. Additionally, a buffer245 may be disposed between the armor layers 235, 240. The buffer 245may be tape and may be made from the lubricative material.

Due to the coaxial arrangement, the cable 80 may have an outer diameter250 less than or equal to one and one-quarter inches, one inch, orthree-quarters of an inch.

Additionally, the cable 80 may further include a pressure containmentlayer (not shown) made from a material having sufficient strength tocontain radial thermal expansion of the dielectric layers and wound toallow longitudinal expansion thereof. The material may be stainlesssteel and may be strip or wire. Alternatively, the cable 80 may includeonly one conductor and the tubing 10 t may be used for the otherconductor.

The cable 80 may be longitudinally fixed to the cablehead 75. Thecablehead 75 may also include leads (not shown) extending therethrough.The leads may provide electrical communication between the conductors ofthe cable 80 and the PCM 55.

The motor 50 may be switched reluctance motor (SRM) or permanent magnetmotor, such as a brushless DC motor (BLDC). The motor 50 may be filledwith a dielectric, thermally conductive liquid lubricant, such as oil.The motor 50 may be cooled by thermal communication with the reservoirwater 100 w. The motor 50 may include a thrust bearing (not shown) forsupporting a drive shaft 50 s (FIG. 4). In operation, the motor 50 mayrotate the shaft 50 s, thereby driving the pump 65. The motor shaft 50 smay be directly connected to the pump shaft (no gearbox). As discussedabove, since the motor may be compact, the motor may operate at highspeed so that the pump may generate the necessary head to pump the water100 w to the surface 20. High speed may be greater than or equal to tenthousand, twenty-five thousand, or fifty-thousand revolutions per minute(RPM). Alternatively, the motor 50 may be any other type of synchronousmotor, an induction motor, or a DC motor.

The SRM motor may include a multi-lobed rotor made from a magneticmaterial and a multi-lobed stator. Each lobe of the stator may be woundand opposing lobes may be connected in series to define each phase. Forexample, the SRM motor may be three-phase (six stator lobes) and includea four-lobed rotor. The BLDC motor may be two pole and three phase. TheBLDC motor may include the stator having the three phase winding, apermanent magnet rotor, and a rotor position sensor. The permanentmagnet rotor may be made of a rare earth magnet or a ceramic magnet. Therotor position sensor may be a Hall-effect sensor, a rotary encoder, orsensorless (i.e., measurement of back EMF in undriven coils by the motorcontroller).

The PCM 55 may include a motor controller (not shown), a modem 55 m(FIG. 4), and demultiplexer (not shown). The modem 55 m anddemultiplexer may demultiplex a data signal from the DC power signal,demodulate the signal, and transmit the data signal to the motorcontroller. The motor controller may receive the medium voltage DCsignal from the cable and sequentially switch phases of the motor,thereby supplying an output signal to drive the phases of the motor. Theoutput signal may be stepped, trapezoidal, or sinusoidal. The BLDC motorcontroller may be in communication with the rotor position sensor andinclude a bank of transistors or thyristors and a chopper drive forcomplex control (i.e., variable speed drive and/or soft startcapability). The SRM motor controller may include a logic circuit forsimple control (i.e. predetermined speed) or a microprocessor forcomplex control (i.e., variable speed drive and/or soft startcapability). The SRM motor controller may use one or two-phaseexcitation, be unipolar or bi-polar, and control the speed of the motorby controlling the switching frequency. The SRM motor controller mayinclude an asymmetric bridge or half-bridge.

Additionally, the PCM may include a power supply (not shown). The powersupply may include one or more DC/DC converters, each converterincluding an inverter, a transformer, and a rectifier for converting theDC power signal into an AC power signal and stepping the voltage frommedium to low, such as less than or equal to one kV. The power supplymay include multiple DC/DC converters in series to gradually step the DCvoltage from medium to low. The low voltage DC signal may then besupplied to the motor controller.

The motor controller may be in data communication with one or moresensors 55 s (FIG. 4) distributed throughout the components 50-75. Apressure and temperature (PT) sensor may be in fluid communication withthe water 100 w entering the intake 65 i. A gas to liquid ratio (GLR)sensor may be in fluid communication with the water 100 w entering theintake 65 i. A second PT sensor may be in fluid communication with thereservoir fluid discharged from the outlet 65 o. A temperature sensor(or PT sensor) may be in fluid communication with the lubricant toensure that the motor and downhole controller are being sufficientlycooled. Multiple temperature sensors may be included in the PCM formonitoring and recording temperatures of the various electroniccomponents. A voltage meter and current (VAMP) sensor may be inelectrical communication with the cable 80 to monitor power loss fromthe cable. A second VAMP sensor may be in electrical communication withthe motor controller output to monitor performance of the motorcontroller. Further, one or more vibration sensors may monitor operationof the motor 50, the pump 65, and/or the seal section 60. A flow metermay be in fluid communication with the discharge 65 o for monitoring aflow rate of the pump 65. Utilizing data from the sensors, the motorcontroller may monitor for adverse conditions, such as pump-off, gaslock, or abnormal power performance and take remedial action beforedamage to the pump 65 and/or motor 50 occurs.

The seal section 60 may isolate the water 100 w being pumped through thepump 65 from the lubricant in the motor 50 by equalizing the lubricantpressure with the pressure of the reservoir fluid 100. The seal section60 may rotationally fix the motor shaft to a drive shaft of the pump.The shaft seal may house a thrust bearing capable of supporting thrustload from the pump. The seal section 60 may be positive type orlabyrinth type. The positive type may include an elastic, fluid-barrierbag to allow for thermal expansion of the motor lubricant duringoperation. The labyrinth type may include tube paths extending between alubricant chamber and a reservoir fluid chamber providing limited fluidcommunication between the chambers.

The pump may include an inlet 65 i. The inlet 65 i may be standard type,static gas separator type, or rotary gas separator type depending on theGLR of the water 100 w. The standard type intake may include a pluralityof ports allowing water 100 w to enter a lower or first stage of thepump 65. The standard intake may include a screen to filter particulatesfrom the reservoir fluid. The static gas separator type may include areverse-flow path to separate a gas portion of the reservoir fluid froma liquid portion of the reservoir fluid.

The pump 65 may be dynamic and/or positive displacement. The dynamicpump may be centrifugal, such a radial flow, mixed axial/radial flow, oraxial flow, or a boundary layer (a.k.a. Tesla pump). The centrifugalpump may include a propeller (axial) or an open impeller (radial oraxial/radial). The pump housing of the centrifugal pump may include anozzle to create a jet effect. The positive displacement may be screw ortwin screw. The pump 65 may include one or more stages (not shown). Eachstage may be the same type or a different type. For example, a firststage may be a positive displacement screw stage and the second stagemay be centrifugal axial flow (i.e., propeller). An outer surface of thepropeller, impeller, and/or screw may be hardened to resist erosion(i.e., carbide coated). The pump may deliver the pressurized reservoirfluid to an outlet 65 o of the isolation device 70.

The pumping system 1 may further include an actuator (not shown) forsetting and/or unsetting the isolation device 70. The actuator mayinclude an inflation tool, a check valve, and a deflation tool. Thecheck valve may be a separate member or integral with the inflationtool. The inflation tool may be an electric pump and may be inelectrical communication with the motor controller or include a separatepower supply in direct communication with the power cable. Uponactivation, the inflation tool may intake reservoir fluid, pressurizethe reservoir fluid, and inject the pressurized reservoir fluid throughthe check valve and into the isolation device. Alternatively, theinflation tool may include a tank filled with clean inflation fluid,such as oil for inflating the isolation device 70.

The isolation device 70 may include a bladder (not shown), a mandrel(not shown), anchor straps (not shown), and a sealing cover (not shown).The mandrel may include a first fluid path therethrough for passing thewater 100 w from the pump 65 to the outlet 65 o, the outlet 65 o, and asecond fluid path for conducting reservoir fluid from the inflation toolto the bladder. The bladder may be made from an elastomer and bedisposed along and around an outer surface of the mandrel. The anchorstraps may be disposed along and around an outer surface of the bladder.The anchor straps may be made from a metal or alloy and may engage aninner surface of the casing 10 upon expansion of the bladder, therebyrotationally fixing the mandrel (and the components 50-75) to the tubing10 t. The anchor straps may also longitudinally fix the mandrel to thecasing, thereby relieving the cable 80 from having to support the weightof the components 50-75 during operation of the pump 65. The cable 80may then be relegated to a back up support should the isolation device70 fail.

The sealing cover may be disposed along a portion and around the anchorstraps and engage the casing upon expansion of the bladder, therebyfluidly isolating the outlet 65 o from the intake 65 i. The deflationtool may include a mechanically or electrically operated valve. Thedeflation tool may in fluid communication with the bladder fluid pathsuch that opening the valve allows pressurized fluid from the bladder toflow into the wellbore, thereby deflating the bladder. The mechanicaldeflation tool may include a spring biasing a valve member toward aclosed position. The valve member may be opened by tension in the cable80 exceeding a biasing force of the spring. The electrical inflationtool may include an electric motor operating a valve member. Theelectric motor may be in electrical communication with the motorcontroller or in direct communication with the cable. Operation of themotor using a first polarity of the voltage may open the valve andoperation of the motor using a second opposite polarity may close thevalve.

Alternatively, instead of anchor straps on the bladder, the isolationdevice may include one or more sets of slips, one or more respectivecones, and a piston disposed on the mandrel. The piston may be in fluidcommunication with the inflation tool for engaging the slips. The slipsmay engage the casing 10, thereby rotationally fixing the components50-75 to the casing. The slips may also longitudinally support thecomponents 50-75. The slips may be disengaged using the deflation tool.

Alternatively, instead of an actuator, hydraulic tubing (not shown) maybe run in with the components 50-75 and extend to the isolation device70. Hydraulic fluid may be pumped into the bladder through the hydraulictubing to set the isolation device 70 and relieved from the bladder viathe tubing to unset the isolation device 70. Alternatively, theisolation device 70 may include one or more slips (not shown), one ormore respective cones (not shown), and a solid packing element (notshown). The actuator may include a power charge, a piston, and ashearable ratchet mechanism. The power charge may be in electricalcommunication with the motor controller or directly with the cable 80.Detonation of the power charge may operate the piston along the ratchetmechanism to set the slips and the packing element. Tension in the cable80 may be used to shear the ratchet and unset the isolation device 70.Alternatively, hydraulic tubing may be used instead of the power charge.Alternatively, a second hydraulic tubing may be used instead of theratchet mechanism to unset the packing element. Alternatively, theisolation device 70 may include an expandable element made from a shapememory alloy or polymer and include an electric heating element so thatthe expandable element may be expanded by operating the heating elementand contracted by deactivating the heating element (or vice versa).

Additionally, the isolation device 70 may include a bypass vent (notshown) for releasing gas separated by the inlet 65 i that may collectbelow the isolation device and preventing gas lock of the pump 65. Apressure relief valve (not shown) may be disposed in the bypass vent.

In operation, to install the pumping system 1, a workover rig (notshown) and the pumping system 1 may be deployed to the wellsite. Sincethe cable 80 may include only two conductors, the cable 80 may bedelivered wound onto a drum (not shown). The wellhead 15 may be opened.The components 50-75 may be suspended over the wellbore 5 from theworkover rig and an end of the cable 80 may be connected to thecablehead 75. The cable 80 may be unwound from the drum, therebylowering the components 50-75 into the wellbore inside of the productiontubing 10 t. Once the components 50-75 have reached the desired depthproximate to the reservoir 25, the wellhead may be closed and theconductors of the cable 80 may be connected to the surface controller45.

Additionally, a downhole tractor (not shown) may be integrated into thecable to facilitate the delivery of the pumping system, especially forhighly deviated wells, such as those having an inclination of more than45 degrees or dogleg severity in excess of 5 degrees per 100 ft. Thedrive and wheels of the tractor may be collapsed against the cable anddeployed when required by a signal from the surface.

The isolation device 70 may then be set. If the isolation device 70 iselectrically operated, the surface controller 45 may be activated,thereby delivering the DC power signal to the PCM 55 and activating thedownhole controller 55. Instructions may be given to the surfacecontroller 45 via the operator interface, instructing setting of theisolation device 70. The instructions may be relayed to the PCM 55 viathe cable. The PCM 55 may then operate the actuator. Alternatively, asdiscussed above, the actuator may be directly connected to the cable. Inthis alternative, the actuator may be operated by sending a voltagedifferent than the operating voltage of the motor. For example, sincethe motor may be operated by the medium voltage, the inflation tool maybe operated at a low voltage and the deflation tool (if electrical) maybe operated by reversing the polarity of the low voltage.

Once the isolation device 70 is set, the motor 50 may then be started.If the motor controller is variable, the motor controller may soft startthe motor 50. As the pump 65 is operating, the motor controller may senddata from the sensors to the surface so that the operator may monitorperformance of the pump. If the motor controller is variable, a speed ofthe motor 50 may be adjusted to optimize performance of the pump 65.Alternatively, the surface operator may instruct the motor controller tovary operation of the motor. The pump 65 may pump the water 100 wthrough the production tubing 10 t and the wellhead 15 into the outlet35, thereby lowering a level of the water 100 w and reducing hydrostaticpressure of the water 100 w on the formation 25. The pump 65 may beoperated until the water level is lowered to the inlet 65 i of the pump,thereby allowing natural production from the reservoir 25. The operatormay then send instructions to the motor controller to shut down the pump65 or simply cut power to the cable 80. The operator may sendinstructions to the PCM 55 to unset the isolation device 70 (ifelectrically operated) or the drum may be wound to exert sufficienttension in the cable 80 to unseat the isolation device 70. The cable 80may be wound, thereby raising the components 50-75 from the wellbore 5.The workover rig and the pumping system 1 may then be redeployed toanother wellsite.

Advantageously, deployment of the components 50-75 using the cable 80inside of the production tubing 10 t instead of removing the productiontubing string and redeploying the production tubing string with apermanently mounted artificial lift system reduces the required size ofthe workover rig and the capital commitment to the well. Deployment andremoval of the pumping system 1 to/from the wellsite may be accomplishedin a matter of hours, thereby allowing multiple wells to be dewatered ina single day. Transmitting a DC power signal through the cable 80reduces the required diameter of the cable, thereby allowing a longerlength of the cable 80 (i.e., five thousand to eight thousand feet) tobe spooled onto a drum, and easing deployment of the cable 80.

FIG. 3 illustrates an electric submersible pumping system 1 deployed ina wellbore 5, according to another embodiment of the present invention.In this embodiment, the casing 10 c has been used to produce fluid fromthe reservoir 25 instead of installing production tubing. In thisscenario, the isolation device 70 may be set against the casing 10 c andthe pump 65 may discharge the water 100 w to the surface 20 via a boreof the casing 10 c.

While the foregoing is directed to embodiments of the present invention,other and further embodiments of the invention may be devised withoutdeparting from the basic scope thereof, and the scope thereof isdetermined by the claims that follow.

The invention claimed is:
 1. A method of unloading water from a naturalgas reservoir, comprising: deploying a downhole assembly of a pumpingsystem into a wellbore and within a tubular string disposed in thewellbore to a location proximate the reservoir using a cable havingcoaxial conductors and a strength sufficient to support a weight of thedownhole assembly and the cable, wherein: the downhole assemblycomprises a motor, an isolation device, and a multi-stage pump, theisolation device has an expandable seal and an anchor, and a maximumouter diameter of the downhole assembly and the cable is less than orequal to two inches; setting the isolation device, thereby rotationallyfixing the downhole assembly to the tubular string and isolating aninlet of the multi-stage pump from an outlet of the multi-stage pump;supplying a direct current (DC) power signal from the surface to thedownhole assembly via the cable extending through a bore of the tubularstring, thereby: operating the motor and multi-stage pump at a speedgreater than or equal to ten thousand revolutions per minute (RPM),pumping the water to the surface through the bore of the tubular string,and lowering a water level in the tubular string bore to a levelproximate the reservoir; and once the water level has been lowered andwhile the water level is lowered in the tubular string bore: unsettingthe isolation device; and removing the downhole assembly from thewellbore using the cable.
 2. The method of claim 1, wherein the downholeassembly further comprises a power conversion module (PCM), and the PCMsequentially switches the DC signal and supplies an output power signalto the motor.
 3. The method of claim 2, wherein the DC power signal issubstantially greater than one kilovolt and the output signal issubstantially greater than one kilovolt.
 4. The method of claim 2,wherein: the DC power signal is substantially greater than one kilovolt,and the PCM includes a power supply operable to reduce the DC powersignal voltage, and the output power signal is less than or equal to onekilovolt.
 5. The method of claim 2, wherein the output power signal isthree phase.
 6. The method of claim 5, wherein the motor is switchedreluctance.
 7. The method of claim 1, wherein: the tubular string is aproduction tubing string hung from the wellhead and isolated from acasing string by a packer, and the casing string is cemented to thewellbore.
 8. The method of claim 1, wherein the speed is greater than orequal to twenty-five thousand RPM.
 9. The method of claim 8, wherein thespeed is greater than or equal to fifty thousand RPM.
 10. The method ofclaim 1, wherein the isolation device is unset by sending a signal viathe cable.
 11. The method of claim 1, wherein the isolation device isunset by exerting tension on the cable.
 12. The method of claim 1,further comprising controlling a speed of the motor.
 13. The method ofclaim 1, wherein the downhole assembly comprises a sensor, and themethod further comprises transmitting a measurement by the sensor to thesurface via the cable.
 14. The method of claim 1, wherein the isolationdevice is set by sending a signal via the cable.
 15. The method of claim1, wherein the isolation device longitudinally fixes the downholeassembly to the tubular string, thereby supporting the weight of thedownhole assembly.
 16. The method of claim 1, wherein the pump iscentrifugal and has a housing including a nozzle operable to create ajet effect.
 17. The method of claim 1, wherein the motor is started andoperated after setting the isolation device.